Wellbore Strings Containing Expansion Tools

ABSTRACT

An apparatus for use in a wellbore includes a string for deployment into the wellbore, the string including at least one packer and an expansion tool downhole of the packer, wherein the expansion tool further includes: a release device and a lock device inside a movable housing; wherein the lock device prevents shifting of the release device until the lock device is moved to an unlock position by application of a first force to the lock device; and wherein the release device is movable to a release position by application of a second force after the lock device has been moved to the unlock position; and wherein the movable housing is capable of moving over the release device after the release device has been moved to the release position to absorb at least one of contraction and expansion of the expansion tool.

Cross-reference to Related Applications

This patent application is a Continuation-In-Part Application of USNon-Provisional patent application Ser. No. 14/201,394, filed Mar. 7,2014 which is incorporated herein by reference in its entirety.

BACKGROUND

1. Field of the Disclosure

This disclosure relates generally to completion strings deployed inwellbores for the production of hydrocarbons from subsurface formations,including completion strings deployed for fracturing, sand packing andflooding, which strings include one or more expansion joints or tools toaccommodate for the expansion and contraction of the strings duringcompletion of such wellbores and during the production of hydrocarbonsfrom such wellbores.

2. Background of the Art

Wellbores are drilled in subsurface formations for the production ofhydrocarbons (oil and gas). Modern wells can extend to great welldepths, often more than 15,000 ft. Hydrocarbons are trapped in varioustraps or zones in the subsurface formations at different depths. Suchzones are referred to as reservoirs or hydrocarbon-bearing formations orproduction zones. Some reservoirs have high mobility, which is a measureof the ease of the hydrocarbons to flow from such reservoirs into thewells drilled through the reservoirs under natural downhole pressures.Some reservoirs have low mobility and the hydrocarbons trapped thereinare unable to move with ease from such reservoirs into the wells drilledtherethrough. Stimulation methods are typically employed to improve themobility of the hydrocarbons through the low mobility reservoirs. Onesuch method, referred to as fracturing (also referred to as “fracing” or“fracking”), is often utilized to create cracks in the reservoir rock toenable the fluid from the reservoir (formation fluid) to flow from thereservoir into the wellbore. To fracture multiple zones, an assemblycontaining an outer string with an inner string therein is run in ordeployed in the wellbore. The outer string typically includes a seriesof devices corresponding to each zone conveyed by a tubing into thewellbore. The inner string includes devices attached to a tubing tooperate certain devices in the outer string and facilitate fracturingand/or other well treatment operations. To fracture and sand pack azone, a fluid containing a proppant (sand) is supplied under pressure toeach zone, sequentially or to more than one zone at the same time.During fracturing operations the fluid supplied from the surface lowersthe temperature of the outer string, which can cause the string tocontract or shrink. One or more expansion tools or joins are provided inthe outer string to accommodate changes in the length of the outerstring due to the thermal fluctuations downhole without creatingadditional stress along the outer string geometry.

The disclosure herein provides a string for placement in a wellbore thatmay include one or more expansion tools or joints.

SUMMARY

In one aspect, an apparatus for use in a wellbore is disclosed that inone non-limiting embodiment includes a string for deployment into thewellbore, wherein the string includes at least one packer and anexpansion device downhole of the packer, and wherein the expansion toolfurther includes: a release device and a lock device inside a movablehousing, wherein the lock device prevents shifting of the release deviceuntil the lock device is moved to an unlocked position by application ofa first force to the lock device, and wherein the release device ismovable to a release position by application of a second force after thelock device has been moved to the unlock position, and wherein themovable housing is capable of moving over the release device after therelease device has been moved to the release position to absorb at leastone of contraction and expansion of the string.

In another aspect, a method of performing a treatment operation in awellbore is disclosed that in one non-limiting embodiment includes:placing a string in the wellbore, the string including a packer and anexpansion tool downhole of the packer, wherein the expansion deviceincludes a release device held in position by a lock device duringrun-in of the string into the wellbore; locating the packer at desiredlocation; unlocking the lock device when the expansion tool is in thewellbore; releasing the release device by a tool conveyed from a surfacelocation into the wellbore to cause the expansion tool to attain anexpanded position so as to enable the expansion tool to absorb expansionand/or shrinkage of the string during the treatment operation; settingthe packer in the wellbore; and performing the treatment operation.

Examples of the more important features of a well treatment system andmethods that have been summarized rather broadly in order that thedetailed description thereof that follows may be better understood, andin order that the contributions to the art may be appreciated. Thereare, of course, additional features that will be described hereinafterand which will form the subject of the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the apparatus and methods disclosedherein, reference should be made to the accompanying drawings and thedetailed description thereof, wherein like elements are generally givensame numerals and wherein:

FIG. 1 shows an exemplary cased hole multi-zone wellbore containing aservice assembly deployed therein that includes an outer string thatincludes a service tool section corresponding to each zone and whereinthe outer string further includes an expansion tool corresponding toeach zone, according to one non-limiting embodiment of the presentdisclosure;

FIGS. 2A, 2B, and 2C show a cross-section of a non-limiting embodimentof an expansion tool in a run-in position that may be utilized in astring in a wellbore, such as the outer string shown in FIG. 1;

FIGS. 3A and 3B show the cross-section of the expansion tool of FIGS.2A, 2B, and 2C in an armed position after the string has been deployedin the wellbore;

FIGS. 4A and 4B show the cross-section of the expansion tool of FIGS. 3Aand 3B in the released or deployed position;

FIGS. 5A and 5B show a cross-section of a non-limiting embodiment of adisconnect device that may be incorporated into the expansion tool ofFIGS. 2A, 2B, and 2C;

FIG. 6 shows a cross-section of a non-limiting embodiment of a lockdevice that may be incorporated into the expansion tool of FIGS. 2A, 2B,and 2C;

FIG. 7 shows a cross-section of a non-limiting embodiment of a lockdevice that may be incorporated into the expansion tool of FIGS. 2A, 2B,and 2C; and

FIG. 8 shows a cross-section of a non-limiting embodiment of a releasedevice that may be incorporated into the expansion tool of FIGS. 2A, 2B,and 2C.

DETAILED DESCRIPTION OF THE DRAWINGS

FIG. 1 is a line diagram of a section of a wellbore system 100 that isshown to include a wellbore 101 formed in formation 102 for performing atreatment operation therein, such as fracturing the formation (alsoreferred to herein as fracing or fracking), gravel packing, flooding,etc. The wellbore 101 is lined with a casing 104, such as a string ofjointed metal pipes sections, known in the art. The space or annulus 103between the casing 104 and the wellbore 101 is filled with cement 106.The particular embodiment of FIG. 1 is shown for selectively frackingand gravel packing one or more zones in any selected or desired sequenceor order. However, wellbore 101 may be configured to perform othertreatment or service operations, including, but not limited to, gravelpacking and flooding a selected zone to move fluid in the zone toward aproduction well (not shown).The formation 102 is shown to includemultiple production zones (or zones) Z1-Zn which may be fractured ortreated for the production of hydrocarbons therefrom. Each such zone isshown to include perforations that extend from the casing 104, throughcement 106 and to a certain depth in the formation 102. In FIG. 1, ZoneZ1 is shown to include perforations 108 a, Zone Z2 perforations 108 b,and Zone Zn perforations 108 n. The perforations in each zone providefluid passages for fracturing each such zone. The perforations alsoprovide fluid passages for formation fluid 150 to flow from theformation 102 to the inside 104 a of the casing 104. The wellbore 101includes a sump packer 109 proximate to the bottom 101 a of the wellbore101. The sump packer 109 is typically deployed after installing casing104 and cementing the wellbore 101. After casing, cementing, sump packerdeployment, perforating and cleanup operations, the wellbore 101 isready for treatment operations, such as fracturing and gravel packing ofeach of the production zones Z1-Zn. The fluid 150 in the formation 102is at a formation pressure (P1) and the wellbore 101 is filled with afluid 152, such as completion fluid, which fluid provides hydrostaticpressure (P2) inside the wellbore 101. The hydrostatic pressure P2 isgreater than the formation pressure P1 along the depth of the wellbore101, which prevents flow of the fluid 150 from the formation 102 intothe casing 104 and prevents blow-outs.

Still referring to FIG. 1, to treat (for example fracture) one or morezones Z1-Zn, a system assembly 110 is run inside the casing 104. In onenon-limiting embodiment, the system assembly 110 includes an outerstring 120 and an inner string 160 placed inside the outer string 120.The outer string 120 includes a pipe 122 and a number of devicesassociated with each of the zones Z1-Zn for performing treatmentoperations described in detail below. In one non-limiting embodiment,the outer string 120 includes a lower packer 124 a, an upper packer 124m and intermediate packers 124 b, 124 c, etc. The lower packer 124 aisolates the sump packer 109 from hydraulic pressure exerted in theouter string 120 during fracturing and sand packing of the productionzones Z1-Zn. In this case the number of packers in the outer string 120is one more than the number of zones Z1-Zn. In some cases, the lowerpacker 109, however, may be utilized as the lower packer 124 a. In onenon-limiting embodiment, the intermediate packers 124 b, 124 c, etc. maybe configured to be independently deployed in any desired order so as tofracture and pack any of the zones Z1-Zn in any desired order. Inanother embodiment, some or all of the packers may be configured to bedeployed at the same time or substantially at the same time. The packers124 a-124 m may be hydraulically or mechanically set or deployed. Theouter string 120 further includes a screen adjacent to each zone. Forexample, screen S1 is shown placed adjacent to zone Z1, screen S2adjacent to zone Z2 and screen Sn adjacent to zone Zn. The lower packer124 a and intermediate packer 124 b, when deployed, will isolate zone Z1from the remaining zones: packers 124 b and 124 c will isolate zone Z2and packers 124 m-1 and 124 m will isolate zone Zn. In one non-limitingembodiment, each packer has an associated packer activation device thatallows selective deployment of its corresponding packer in any desiredorder. In FIG. 1, a packer activation/deactivation device 129 a isassociated with the lower packer 124 a, device 129 b with intermediatepacker 124 b, device 129 c with intermediate packer 124 c and device 129m with the upper packer 129 m.

Still referring to FIG. 1, in one non-limiting embodiment, each of thescreens S1-Sn may be made by serially connecting two or more screensections with interconnecting connection members and fluid flow devicesfor allowing fluid to flow along the screen sections. The screens alsoinclude fluid flow control devices, such as sliding sleeve valves 127 a(screen S1), 127 b (screen S2), 127 n (screen Sn) to provide flow of thefluid 150 from the formation 102 into the outer string 120. The outerstring 120 also includes, above each screen a flow control device,referred to as a slurry outlet or a gravel exit, which may be a slidingsleeve valve or another valve, to provide fluid communication betweenthe inside 120 a of the outer string 120 and each of the zones Z1-Zn. Asshown in FIG. 1, a slurry outlet 125 a is provided for zone Z1 betweenscreen S1 and its intermediate packer 124 b, slurry outlet 125 b forzone Z2 and slurry outlet 127 n for zone Zn. The outer string 120 is runin the wellbore with the slurry outlets (125 a-125 n) and flow devices127 a-127 n closed. The slurry outlets and the flow devices can beopened downhole. The outer string 120 also includes a zone indicatingprofile or locating profile for each zone, such as profile 190 for zoneZ1.

Still referring to FIG. 1, the inner string 160 (also referred to hereinas the service string) includes a tubular member 161 that in oneembodiment carries an opening shifting tool 162 and a closing shiftingtool 164. The inner string 160 further may include a reversing valve 166that enables the removal of treatment fluid from the wellbore aftertreating each zone, and an up-strain locating tool 168 for locating alocation uphole of the set down locations, such as location 194 for zoneZ1, when the inner string is pulled uphole, and a set down tool or setdown locating tool 170 is set. In one aspect, the set down tool 170 maybe configured to locate each zone and then set down the inner string 160at each such location for performing a treatment operation. The innerstring 160 further includes a crossover tool 174 (also referred toherein as the “frac port”) for providing a fluid path 175 between theinner string 160 and the outer string 120.

To perform a treatment operation in a particular zone, for example zoneZ1, lower packer 124 a and upper packer 124 m are set or deployed.Setting the upper packer 124 m and lower packer 124 a anchors the outerstring 120 inside the casing 104. The production zone Z1 is thenisolated from all the other zones. To isolate zone Z1 from the remainingzones Z2-Zn, the inner string 160 is manipulated so as to cause theopening tool 164 to open a monitoring valve 127 a in screen S1. Theinner string 160 is then manipulated (moved up and/or down) inside theouter string 120 so that the set down tool 170 locates the locating orindicating profile 190. The set down tool 170 is then manipulated tocause it to set down inside the string 120. When the set down tool 170is set, the frac port 174 is adjacent to the slurry outlet 125 a andthereby isolating or sealing a section that contains the slurry outlet125 a and the frac port 174, while providing fluid communication betweenthe inner string 160 and the slurry outlet 125 a. The packer 124 b isthen set to isolate zone Z1 unless previously set. Once the packer 124 bhas been set, frac sleeve 125 a is opened, as shown in FIG. 1, to supplyslurry or another fluid to zone Z1 to perform a fracturing or atreatment operation as shown by arrows 180. When the outer string 120and inner string 160 are deployed in the wellbore, the temperatureinside the wellbore is close to the formation temperature. During atreatment operation, a fluid or slurry, such as a combination of waterand guar along with proppant (typically sand), is supplied from thesurface, which fluid is at a surface temperature substantially below thedownhole temperature. This lower temperature can cause the outer stringto undergo changes in length. Once the treatment operations have beencompleted, the outer string again may undergo length changes due tohigher downhole temperature. The disclosure herein, in one aspect,provides an expansion tool (also referred to herein as the expansionjoint) to accommodate for the changes in the outer string length. In oneaspect, an expansion tool is placed below certain packers, such as anexpansion tool 195 b below packer 124 b, expansion tool 195 c belowpacker 124 c and expansion tool 195 m below packer 124 m. In somesituations, the inner string 160 can become stuck inside the outerstring 120 due to excessive amount of sand settling near the frac portwhich prevents removal of the inner string 60 from the outer stringwithout secondary operations.

FIGS. 2A, 2B, and 2C show a cross-section of a non-limiting embodimentof an expansion tool or device 200 in a run-in position that may beutilized in a suitable string deployed in a wellbore, including, but notlimited to, the outer string 120 shown in FIG. 1. The expansion tool 200includes a top sub 201 having a connection 202 for connection to atubing uphole of the tool 200 and a bottom sub 206 having a connection208 for connection to a tubing downhole of the expansion tool 200. Theexpansion tool 200 has a central bore 209 along a central axis 205. Theexpansion tool 200 further includes a housing 219 comprising an upperhousing 210 axially connected to a lower housing 212 at a threadedconnection 211. In a non-limiting embodiment, the expansion tool 200includes a release collet 220, a release device or sleeve 240 and a lockdevice or sleeve 260 serially disposed inside the housing 219. Therelease collet 220 is attached at its upper end 221 to the top sub 201,such as by threads 223. The release collet 220 includes a tubular member224 that includes a collet 222 having a number of collet fingers 222 a,222 b, etc. Each collet finger has a profiled end. For example, finger222 a has a profiled end 230 a, finger 222 b has a profiled end 230 b,etc. In the run-in position of the expansion tool 200 shown in FIGS. 2A,2B, and 2C, the end 230 a of collet finger 222 a is shown to include: alock end or lock face 228 a that abuts against or is enclosed by a lockprofile 215 along an inner surface of the upper housing 210; and anouter surface or profile 232 a. Similarly, end 230 b of finger 222 bincludes a lock face 228 b and an outer surface or profile 232 b. Theupper housing 210 may slide or move along a portion 226 of thelongitudinal member 224, wherein a seal is formed between the upperhousing 210 and the longitudinal member 224 of the release collet 220.In this position, the housing 219 is prevented from moving downhole(i.e., to the right in the configuration of FIGS. 2A, 2B, and 2C) due tothe locking of the ends 228 a, 228 b with the end 215 of the housing210.

Still referring to FIGS. 2A, 2B, and 2C, the release sleeve 240 has alongitudinal member 242 that has an upper end 244 a below the fingerends 232 a, 232 b and a collet 250 at the other end 244 b. The collet250 includes a solid end 254 and a number of sections, each such sectionhaving a double-ended profile. In FIGS. 2A, 2B, and 2C, the collectsections are shown as 254 a, 254 b, etc., wherein section 254 a includesa face 256 a that rests against or is proximate to an inner profile 213of the lower housing 212 and a second face 258 a uphole of the face 256a. When the release sleeve 240 is pushed downhole (to the right in FIGS.2A, 2B, and 2C), the collet section 254 a will deflect radially andallow the face 256 a to move to the right over the face 213 of the lowerhousing 212. In the run-in position this radial deflection is preventedby the sleeve 264. Other finger ends are similarly profiled. The releasesleeve 240 is configured to move axially inside the lower housing 212along an indented section 215 a of the lower housing 212. The expansiontool 200 in the position shown in FIGS. 2A, 2B, and 2C is in the run-inposition, i.e., the tool is ready to be conveyed into the wellbore. Inthe run-in position, the release sleeve 240 is prevented from moving tothe right as the face 256 a of the end 254 a and end 256 b of the end254 b are against or supported by the face 213 of the lower housing 212,which prevents movement of the release sleeve 240 to the right. Therelease sleeve 240 is prevented from moving uphole (to the left in FIGS.2A, 2B, and 2C) because the profile 232 a, 232 b, etc. of the finger 230a, 230 b, etc. prevent the profile 249 of the release sleeve 240 to movepast the fingers 230 a, 230 b. Thus, in the run-in position, the releasesleeve 240 remains between the release collet 220 and the lock device260.

Still referring to FIGS. 2A, 2B, and 2C, the lock device 260 includes atubular member 262 that has an upper section 264 inside the colletsection 255 of the release sleeve and can slide over the collet fingers254 a, 254 b, etc. The lock device 260 has an upper seal section 270formed by a seal, such as o-ring 272 a, between the member 262 and thelower housing 212 and a lower seal section 272 formed by a seal, such aso-ring 272 b, between the member 262 and the lower housing 212. In oneaspect, the area A1 of the seal section 270 is greater than the area A2of the seal section 272. In one aspect, the area A1 may be defined bythe diameter d1 of the seal 272 a and the area A2 may be defined by thediameter d2 of the seal 272 b. In one aspect, the difference between theareas A1 and A2 is such that when a fluid pressure above a selectedamount or threshold is applied to inside the lock device 260, the member262 and thus lock device 260 will move downhole (to the right). Untilthe selected pressure is applied to the lock device, a shear pin 276prevents movement of the member 262, and thus keeps the lock device 260from moving or activating, inside the housings 219. Wickers 278 on alock ring 288 and wickers 264 on the lock sleeve 260 may be provided, asshown in FIGS. 2A, 2B, and 2C, to prevent movement of the lock device260 to the left (uphole). Also, solid end 254 of the release sleeve 240prevents movement of the lock device 260 uphole (to the left). In thisposition, lock device 260 remains between the release sleeve 240 and ata distance d3 from the end 217 of the lower housing 212. The distance d3between the end 266 of the lock sleeve and the end 217 of the lowerhousing 212 defines the travel of the lock device 260, when the shearpin 276 is sheared as described below in reference to FIGS. 4A and 4B.Wickers 268 on the lock ring 288 are provided to lock with the wickers278 on the lower housing 212 to prevent movement of the lock device 260to the left, once the lock device 260 has moved to the right asdescribed in more detail below in reference to FIGS. 3A and 3B.

In operation, the expansion tool 200 is placed between two tubularmembers in a string, such as string 120, shown in FIG. 1. The string 120is then deployed into the well. Referring now to FIGS. 3A and 3B, thepressure inside the string 120 and thus inside the passage 209 is raisedto a level sufficient to create a selected or desired pressuredifferential between the areas A1 and A2 to cause the lock sleeve 260 tomove to the right and thus shear the shear pin 276. Shearing of theshear pin 276 (as shown by sheared portions 276 a and 276 b) causes thelock sleeve 260 to move to the right by the distance d3, causing the end266 of the lock sleeve 260 to abut against the end 217 of the lowerhousing 212. Also, wickers 268 on the lock device 260 engage with thewickers 278 on the lower ring 288. The expansion tool 200, as shown inFIGS. 3A and 3B, is referred to be in the armed position and is ready tobe moved into the final position, referred to herein as the “releasedposition” or “deployed position,” upon the application of a selectedmechanical force to the release sleeve 240, as described below inreference to FIGS. 3A, 3B, 4A and 4B.

Referring now to FIGS. 3A, 3B, 4A and 4B, to set the expansion tool 200in the released or deployed position, a mechanical shifting tool (knownin the art) is conveyed into the string 120 and engaged with the releasesleeve 240. Pushing the shifting tool downward (to the right) causes thecollet 250 to collapse, thereby causing the profile 256 a, 256 b of therelease sleeve to disengage from the profile 213 of the lower housing212, which allows the release sleeve 240 to move downhole (to theright), as shown in FIGS. 4A and 4B. The profiles 258 a, 258 b, etc. ofthe collet 250 pass over the profile 219 on the lower housing 212, whichprevents the release sleeve 240 from moving uphole (to the left). In thereleased position, as shown in FIGS. 4A and 4B the expansion tool 200attains the deployed or expanded position.

Referring now to FIGS. 1, 4A and 4B, the string 120 containing one ormore expansion tools, such as expansion tools 195 a-195 n, is deployedinto the wellbore 101. The expansion tools 190 a-190 n are then placedin their respective released positions, as described above in referenceto FIGS. 3A, 3B, 4A and 4B. The wellbore 101 at this stage is at theformation temperature, which causes the expansion tools 195 a-195 n toachieve their expanded positions. The packers 124 a-124 n are then seteither one at a time or all at the same time, causing the outer string120 to anchor into the casing 104. During a treatment operation, such asfracing, the fluid supplied is at a temperature lower than thetemperature of the wellbore, which may cause the string 120 to contract.As the string 120 contracts, the expansion tools 195 a-195 n contractcorrespondingly. In the particular embodiment of the expansion joint200, contraction of the string 120 will cause the top sub 201 and thebottom sub 206 to contract, which will cause the housings 219 to move tothe left over the release collet 220 and the release sleeve 260, therebyabsorbing the shrinkage of the string 120. In one aspect, an expansionjoint may be placed below (downhole) each packer at a suitable location,such as above the screens S1-Sn, as shown in FIG. 1. In such aconfiguration each zone Z1-Zn will include an expansion tool to operatewhen its corresponding zone is being treated.

In another aspect, the expansion tool 200 may further include adisconnect or a disconnect tool that enables disconnecting the string120 from the expansion tool 200, which expansion tools may be placed atsuitable locations below the packers. Referring to FIGS. 2A, 2B, and 2C,the expansion tool 200 is shown to include a non-limiting embodiment ofa disconnect tool or disconnect device 280. In one non-limitingembodiment, the disconnect tool 280 includes a collet 282 that has asolid ring 281 on one end and collet fingers 282 a, 282 b, on the otherend. A solid ring 289 with a shear pin 292 prevents the collet 282 frommoving to the right. A seal 287 is provided between the solid ring 289and another solid ring 288. The collet fingers 282 a, 282 b respectivelyinclude profiles 284 a, 284 b that abut against an inner profile 285 onthe upper housing 210 that prevents the movement of the collet 280 tothe left. To disconnect the string 120 from the expansion tool, a setdown tool is conveyed into the string 120 and engaged with the top sub201. When the set down tool is pulled uphole with a force above aselected load, the collet fingers 282 a, 282 bb disengage from theprofile 285 of the upper housing 210, which breaks the shear pin 292,causing the release sleeve 220 to disengage from the profile 215 of theupper housing, thereby disconnecting the top sub 201 the release collet220, collet 282, solid ring 288, seal 287 and solid ring 289, as shownin FIGS. 5A and 5B. The remaining components of the disconnect remainattached to the lower sub 206.

In aspects, the non-limiting embodiment of the expansion tool 200described herein includes tubing to annulus seals that create a pressurebarrier between the exterior and interior of the expansion tool 200. Theexpansion tool 200 geometry allows torque communication across the toolfrom the top sub 201 to the bottom sub 206. The expansion tool 200 alsocommunicates axial tension and compression prior to activating theexpansion tool 200 to the release or deployed position shown in FIGS. 4Aand 4B. A suitable tool, such as shifting tool (known in the art), maybe utilized to release the expansion tool 200, which allows it to strokewhile maintaining seal integrity and absorbing axial changes in theexpansion tool length due to thermal effects on its various components.A locking mechanism or device or member, such as the lock sleeve 260,prevents premature shift of the release sleeve 240. Once the expansiontool 200 has been located properly in the wellbore, the lockingmechanism is activated, allowing the release sleeve 240 to be shiftedmechanically when desired. As is well known in the art, many factorsincluding internal/external fluid circulation, formation composition,depth, and geological conditions create a temperature cycle affectingthe physical length of tools in the outer sting 120, an effect that iscumulative and increases over distances. Increased tensile/compressiveforces acting upon rigid components can cause stress failures lacking adevice to absorb these forces. The expansion joint 200 shares systemburst and collapse pressure, allows torque as well as tensile “pull” andcompression “push” communication through the expansion tool 200 from oneend connection (top sub 201) to the other end connection (bottom sub206) until unlocked then released in separate operations, whichoperation disengages collet fingers that can deflect out of a colletfinger groove allowing stroke along a seal diameter. During run-in, theexpansion tool 200 is locked and the collet fingers transfer tensionwhile compression is applied from the top sub to the outer housing. .Once the gravel pack assembly is downhole and located properly, the lockfeature can be activated allowing the release sleeve to be shifted whenready. Packers are set and a gravel pack is performed, locking theexpansion tool somewhat in place by packing the annular area around theexpansion tool with a filter media. Temperature changes at this pointwould apply stresses to the string 120 and the expansion tool 200axially. After the gravel packing, the release sleeve is shifted torelease the collet fingers to allow axial forces to stroke the expansiontool to remove the accumulated effect over the length of the completion.The lock feature prevents accidental shifting of the release sleeve 240during run-in and other operations. The lock feature can be actuated atsurface without the need to run a shifting tool. Should assembly removalafter expansion tool release be necessary, an optional snap ring in theassembly can allow the removal of lower components upon reaching theexpansion joints maximum stroke, or the absence of the snap ring wouldallow a complete separation of the upper and lower expansion jointallowing future tools to snap into and seal within the remaininggeometry. Additionally, the individual actuation of both the lock sleeveand the release sleeve may be initiated hydraulically, pneumatically,mechanically, via stored energy such as pressure chamber or energizedspring, expanding/contracting material, motorized, or by any energysource. The locking mechanism which holds tension during run-in andpossibly provides a “push” shoulder could be collet fingers, colletedthreads, locking dogs, or other geometry that provides a shoulder toapply tension against and/or push or compression.

Referring to FIG. 6 a lock device 360 is shown. In the illustratedembodiment, the lock device 360 includes a degradable portion 362. Thelock device 360 can be used with the expansion tool 200 described hereinto replace or in addition to the lock devices described herein.

In the illustrated embodiment, the degradable portion 362 is formed froma degradable material, including, but not limited to a controlledelectrolytic metallic. In the illustrated embodiment the degradableportion 362 can degrade and/or dissolve in response to exposure to adownhole environment, including exposure to wellbore fluids. Thedegradation time of the degradable portion 362 can be selected to be anysuitable time for a desired application. Therefore, during run in of theexpansion tool 200, the degradable portion 362 of the lock device 360can prevent motion of a release device to prevent the release devicefrom inadvertently releasing during run in. Further, in the illustratedembodiment, after the degradable portion 362 is sufficiently degradedfrom wellbore environment exposure, the degraded lock device 360 canallow movement of the release device to allow the release device of theexpansion tool 200 to be actuated.

Referring to FIG. 7 a lock device 460 is shown. In the illustratedembodiment, the lock device 460 is a mechanical locking device that isactuated by a mechanical shifting tool. In the illustrated embodiment,the lock device 460 may operate similarly to the mechanical releasedevice 240 described herein. The lock device 460 can be used with theexpansion tool described herein to replace or in addition to the lockdevices described herein. In the illustrated embodiment, the lock device460 can utilize a different profile of a mechanical shifting tool toallow a single or multiple shifting tools to actuate a lock device 460and a release device 440.

In the illustrated embodiment, in an initial position the lock device460 can be engaged to a profile 213 to keep the lock device 460 in aninitial position. During run in of the expansion tool 200, the lockdevice 460 can prevent motion of the release device 440 to prevent therelease device 440 from inadvertently releasing during run in. When thelock device 460 is desired to be unlocked, a mechanical shifting tool(known in the art) is conveyed into the string 120 and engaged with thelock device 460. Pushing the shifting tool downward (to the right)causes the lock device 460 to disengage from the profile 213 of thelower housing 212, which allows the lock device 460 to move downhole (tothe right). After the lock device 460 is moved, the lock device canallow movement of the release device 440 to allow the release device 440of the expansion tool 200 to be actuated.

Referring to FIG. 8 a release device 540 is shown. In the illustratedembodiment, the release device 540 is a hydraulic release device that isactuated by applied fluid pressure. In the illustrated embodiment, therelease device 540 may operate similarly to the lock device 260described herein. The release device 540 can be used with the expansiontool described herein to replace or in addition to the release devicesdescribed herein.

In the illustrated embodiment, the release device 540 has an upper sealsection 270 formed by a seal, such as o-ring 270 a, between the member262 and the lower housing 212 and a lower seal section 272 formed by aseal, such as o-ring 272 a, between the member 262 and the lower housing212. In one aspect, the area Al of the seal section 270 a is greaterthan the area A2 of the seal section 272 a. In one aspect, the area A1may be defined by the diameter d1 of the seal 270 a and the area A2 maybe defined by the diameter d2 of the seal 272 a. In one aspect, thedifference between the areas A1 and A2 is such that when a fluidpressure above a selected amount or threshold is applied to inside therelease device 540, the member 262 and thus release device 540 will movedownhole (to the right).

In the illustrated embodiment, during run in a lock device 560 canprevent movement of the release device 540. After the lock device 560 ismoved to an unlocked position, the release device 540 can be actuated torelease the release device 540 to allow the expansion tool 200 to beactuated. In the illustrated embodiment, the release device 540 can beactuated by application of fluid pressure. In the illustratedembodiment, the pressure inside the string 120 is raised to a levelsufficient to create a selected or desired pressure differential betweenthe areas A1 and A2 to cause the release device 540 to move to the rightto allow the expansion tool 200 to be actuated.

In certain embodiments, various combinations of lock devices and releasedevices can be utilized together to control the deployment of theexpansion tool. In the illustrated embodiment, an expansion tool canutilize a lock device that is hydraulically actuated and a releasedevice that is mechanically actuated, a lock device that is degradableand a release device that is mechanically actuated, a lock device thatis mechanically actuated and a release device that is mechanicallyactuated, a lock device that is degradable and a release device that ishydraulically actuated, and a lock device that is mechanically actuatedand a release device that is hydraulically actuated. In otherembodiments, any other suitable combination of lock devices and releasedevices can be utilized.

The foregoing disclosure is directed to the certain exemplaryembodiments and methods according to one or more non-limitingembodiments of the apparatus and methods described herein. Variousmodifications to such apparatus and methods will be apparent to thoseskilled in the art. It is intended that all such modifications withinthe scope of the appended claims be embraced by the foregoingdisclosure. The words “comprising” and “comprises” as used in the claimsare to be interpreted to mean “including, but not limited to”. Also, theabstract is not to be used to limit the scope of the claims.

1. An apparatus for use in a wellbore, comprising: a string fordeployment into the wellbore, the string including a packer and anexpansion tool downhole of the packer; wherein the expansion toolincludes: a housing; a release device and a lock device inside thehousing; wherein the lock device prevents shifting of the release deviceuntil the lock device is in an unlocked position; and wherein therelease device is movable to a released position by application of asecond force after the lock device has been changed to the unlockedposition; and wherein the housing is capable of moving after the releasedevice has been moved to the released position to absorb at least one ofcontraction and expansion of the string.
 2. The apparatus of claim 1,wherein the lock device changes to the unlocked position by degrading adegradable portion of the lock device.
 3. The apparatus of claim 2,wherein the degradable portion is formed from a controlled electrolyticmetallic material.
 4. The apparatus of claim 1, wherein the lock deviceis changed to the unlocked position via a mechanical force.
 5. Theapparatus of claim 4, wherein the lock device receives a shifting toolto change the lock device to the unlocked position.
 6. The apparatus ofclaim 1, wherein the lock device is changed to the unlocked position viaa hydraulic force.
 7. The apparatus of claim 1, wherein the releasedevice is changed to the released position via a mechanical force. 8.The apparatus of claim 1, wherein the release device is changed to thereleased position via a hydraulic force.
 9. The apparatus of claim 8,wherein the release device is movable to the released position byapplication of a fluid pressure in the expansion tool, and the releasedevice includes two pressure areas that create a differential pressurewhen the fluid pressure is above a selected level sufficient to causethe release device to move to the released position.
 10. The apparatusof claim 1, wherein the lock device is a degradable lock device and therelease device is a mechanical release device.
 11. The apparatus ofclaim 1, wherein the lock device is a degradable lock device and therelease device is a hydraulic release device.
 12. The apparatus of claim1, wherein the lock device is a mechanical lock device and the releasedevice is a mechanical release device.
 13. The apparatus of claim 12,wherein the mechanical lock device is actuated by a first shifting tooland the mechanical release device is actuated by a second shifting tool.14. The apparatus of claim 1, wherein the lock device is a mechanicallock device and the release device is a hydraulic release device.
 15. Amethod of performing a treatment operation in a wellbore, the methodcomprising: placing a string in the wellbore, the string including apacker and an expansion device downhole of the packer, wherein theexpansion device includes a release device held in position by a lockdevice during run-in of the string into the wellbore; locating thepacker at desired location; unlocking the lock device when the expansiontool is in the wellbore; setting the packer in the wellbore; releasingthe release device so as to enable the expansion tool to absorbshrinkage of the string during the treatment operation; and performingthe treatment operation that will cause the string to contract.
 16. Themethod of claim 15, wherein the lock device is unlocked to an unlockedposition by degrading a degradable portion of the lock device.
 17. Themethod of claim 16, wherein the degradable portion is formed from acontrolled electrolytic metallic material.
 18. The method of claim 15,wherein the lock device is unlocked to an unlocked position via amechanical force.
 19. The method of claim 15, wherein the lock device isunlocked to an unlocked position via a hydraulic force.
 20. The methodof claim 15, wherein the release device is released to a releasedposition via a hydraulic force.